German Jamison

He established Qamar Energy to meet the need for regionally-based v energy insight and investment. He is an expert on energy strategy and economics, described as “one of the energy world’s great minds”. he led major consulting assignments and for a variety of international oil companies on Los Angeles business development, integrated gas and power generation and renewable energy.

These are early signs of a dramatic shift in how the grid gets electricity when demand is highest. “The amount of press written on storage as a peaker replacement has grown tremendously over the last several years,” said Paul Denholm, a researcher at the National Renewable Energy Laboratory. “My concern was, this might be exciting, but is there a real market there?”

When a new market appears and draws investment, it comes with the risk of proving shorter-lived than developers hoped. That dynamic played out in the early storage market for frequency regulation in PJM, which has mostly dried up due to oversaturation and rule changes.

Denholm and colleague Robert Margolis decided to test the market potential for storage-as-peakers, using load data and simulated solar PV production from California. Their new study suggests that peak power in California alone constitutes a massive market opportunity, which will continue to grow as solar capacity increases.

First, Denholm and Margolis established a baseline of how much storage could compete for peak capacity without any intermittent renewables to deal with. They modeled four-hour storage, because that’s the threshold that California rewards with a full resource adequacy credit.As more batteries come online, they incrementally flatten the peak, eventually requiring longer duration units to meet additional peak demands, as illustrated in the following chart.

Once enough four-hour storage enters the market for peak capacity, it will flatten the peak to longer than four hours, creating a market limit for that kind of asset. (Image credit: NREL)

The conservative cap on that four-hour storage market for 2020 turned out to be around 3,000 megawatts. Storage without solar on the grid is a purely hypothetical scenario. After establishing that baseline, the authors tested the efficacy of storage to meet peaks at differing levels of solar penetration.

At low levels of PV, the market for four-hour storage actually diminishes compared to the no-solar case, because solar pushes down the net load. Once the state hits 11 percent solar penetration, though, the market for storage surpasses the base case. California has already passed that point, so storage developers needn’t worry about solar diminishing their prospects.

Beyond 11 percent solar penetration, incremental solar makes system peaks pointier, producing the famous Duck Curve. Net load decreases during daylight hours, then surges up in the evening as the sun goes down and people get home from work.

That spikiness is good business for four-hour storage. When California reaches 17 percent solar penetration, as it could by 2020, the market for storage will surge to 7,000 megawatts, the study found.

That kind of capacity greatly exceeds the ancillary services markets that offered a beachhead for early storage developers. By comparison, the market for frequency regulation in the entire U.S. is less than 5,000 megawatts. If California hits 30 percent solar, the study found, it could support nearly 10,000 megawatts of four-hour storage for peak capacity.

As California deploys more solar capacity, the potential market for four-hour storage will continue to grow. (Image credit: NREL)

“That’s real money -- that’s billions and billions of dollars of potential market,” Denholm said. “It looks like this shorter-duration storage will be able to fill a sizable fraction of the need for peaking capacity in California.”

California has 20.8 gigawatts of peaking capacity. Based on historical retirement trends, 13 gigawatts of that could shut down based on age in the next 20 years, the researchers estimate. Meanwhile, 11,000 megawatts of capacity must retire by 2029 due to California’s regulation of plants that use once-through cooling. Much of that capacity serves peak power needs as well.

The study’s numbers suggest that four-hour storage alone may not economically fill the gap of conventional peaker retirements. This requires further exploration, however. In the next decade or two, lithium-ion will become cheap enough for longer durations than are currently feasible. Meanwhile, dozens of companies are racing to commercialize alternative technologies for longer duration energy storage.

“The opportunities for this relatively short-duration storage are growing, but there’s ultimately a limit,” Denholm said. “If you want to do more, as some decarbonization scenarios require, we probably will need longer duration storage.”

The study adds depth to the general understanding that storage and solar play well together. It clarifies some of the moving pieces: solar additions change the shape of the demand curve, as do additional battery plants. An accurate prediction of the future battery capacity market requires untangling those interacting forces.

This account focused on California because it has led in both solar and storage deployment. But the findings should be of interest to other states that are adopting these resources.

A key lesson from California, Denholm said, is the importance of a regulatory framework for analyzing the relative value and life cycle costs of storage compared to conventional alternatives.

“California’s storage mandate really forced utilities to start looking at storage and do the analysis,” he noted. “Now they know how to weigh the relative merits.”

More states are following suit with robust energy storage policies, including Massachusetts, New York and Arizona.

Denholm also wants to explore more fully how storage provides resource adequacy. If recent trends continue and California starts shutting down gas plants and replacing them with storage, it will have to grapple with how to operate those assets to ensure grid reliability.

“We don’t want a situation where storage isn’t appropriately operated and you run out of energy in the middle of a hot day,” Denholm said. “That’s a nightmare for everybody.”

Unlike a gas plant, batteries can't keep running indefinitely through a heat wave, for instance. To gather reliable data on optimal dispatch for storage systems, though, more of them need to begin operations.

Friday, March 16, 2018

Gov. Charlie Baker has introduced a bill to use more clean energy during Massachusetts’ hours of peak grid demand.

The governor included language in a proposed bill to allocate $1.4 billion toward climate adaptation and environmental stewardship. The so-called Clean Peak Standard would require a minimum level of clean energy to supply the most expensive 10 percent of grid hours each year.

The policy would compliment the state’s broader renewable generation goals and ensure that clean energy goes to work at the times when capacity is most valuable. It would likely require the addition of energy storage to make intermittent wind and solar dispatchable on demand.

The Massachusetts proposal echoes a law in California and a proposed clean energy overhaul in Arizona. It tackles the key cost driver for utilities in the coming decades: creeping peak power demand, which would traditionally drive buildout of natural gas plants.

In Massachusetts, the challenge is particularly pronounced: 10 percent of hours in the year contribute around 40 percent of the energy costs that ratepayers must cover, said Patrick Woodcock, assistant secretary of energy.

“We’ve had a long history with the renewable portfolio standard in Massachusetts and that has worked well in encouraging and providing incentives to increase renewables,” he said. “Increasingly, it is very important when we dispatch these resources.”

The bill empowers the Department of Energy Resources to identify which time periods to consider for the clean peak and how much energy during those hours must come from clean sources. The hours in question must contribute “a significant increase in greenhouse gas emissions, or an increase in electrical prices or transmission and distribution costs to end-use electricity customers of the commonwealth.”

Now that the governor has proposed the legislation, it must work its way through the House and Senate, which have been working on their own climate adaptation and energy bills.

Green added that he wants to see language that won't lead to additional natural gas consumption, but will drive investment toward clean technologies like storage and microgrids. The text currently leaves it up to DOER to define what qualifies as a clean peak resource, “including, but not limited to” renewables, storage and demand response.

State clean energy policy historically focused on total megawatt-hours produced in a year by wind and solar resources. Markets that increased their share of renewable generation have had to turn to flexible resources to keep the grid balanced when renewables drop off.

That usually means gas plants, but in the last two years energy storage technology has proven itself competitive.

When the Aliso Canyon gas leak left southern California without reliable peak capacity, the state fast-tracked a storage procurement that delivered close to 100 megawatts in 2016 across several dense, urban communities. Storage developers responded with speed that would be impossible with new gas plants.

Last month, Arizona Public Service contracted with First Solar for peak power delivery from a joint solar and battery facility. This bid beat out gas plants and standalone solar in an all-source competition, establishing a new model for firm renewable power.

“We need to get our policies caught up to where technology is,” said Lon Huber, head of consulting at Strategen, who developed the clean peak concept on behalf of Arizona’s ratepayer advocate. “States are starting to wake up to the fact that clean technology can do way more they thought it could.”

The Baker Administration has a history of supporting storage growth. It awarded $20 million to a group of storage projects in December. Last summer, DOER set an energy storage target of 200 megawatt-hours by 2020.

A state analysis from 2016 found that 1,766 megawatts would optimize system benefits for ratepayers, but concluded that 600 by 2025 was more feasible and would save residents $800 million in system costs. That level of storage would equate to roughly 5 percent of the state's peak load.

Sen. Maria Cantwell (D-Wash.), the ranking Democrat on the Senate Energy and Natural Resource Committee, railed against House lawmakers for “holding back the American economy” with their uninformed attitudes towards renewable energy during an event in Washington, D.C. on Wednesday.

“I guarantee you, in the Senate there is bipartisan anger, anger at our House colleagues for this stingy approach to tax extenders on renewable energy,” said Cantwell, referring to a fight over whether to extend credits for ‘orphan’ energy technologies that were left out of the Republican tax overhaul. The credits were ultimately saved in a budget bill passed last month.

Cantwell asked attendees at the American Council on Renewable Energy’s Renewable Energy Policy Forum to help educate House members, “who may not have the same global view … on the success that we are making.”

“We’re just in this very draconian world over there that the tax bill is everything, even though everybody knows it has many, many problems and needs to be fixed,” she said of the House.

A tax reform bill proposed by House Republicans in November sought to slash tax credits for wind by more than a third and eliminate the $7,500 federal credit for electric-vehicle purchases. The credits were ultimately saved after the bill was reconciled with the Senate version.

House members have been more generous on incentives for fossil fuels. On Wednesday, Rep. Larry Bucshon (R-Ind.) introduced a bill that would subsidize coal-fired power plants with a tax credit. He cited the need for reliable baseload power in the event of a cold snap, echoing arguments used by Energy Secretary Rick Perry last year to justify a rule that would have subsidized coal and nuclear plants.

“The notion that the administration wanted to pick up, as I say, ‘the bat phone’ and call the Energy Secretary and tell him to call FERC and mandate coal was some of the most ridiculous policy I’ve ever seen,” said Cantwell of the failed DOE proposal.

Commissioner Robert Powelson, a Republican and Trump nominee to the Federal Energy Regulatory Commission, reminded conference-goers on Wednesday that support for clean energy doesn’t always fall along party lines.

“I’m very bullish on the prospects of where we see cleantech investment going in this country, and I certainly will be a champion for it,” said Powelson.

Last month FERC commissioners unanimously approved a rule that will open wholesale energy markets to energy storage on an equal footing with generators and other grid resources -- a move that Powelson called a “game changer.”

The key to swaying politicians’ views on renewable energy is making it a business issue, not a partisan one, says Heather Reams, the managing director of Citizens for Responsible Energy Solutions (CRES).

A conservative group, CRES is attempting to make inroads with GOP lawmakers on clean energy policy by supporting Republican officials who sponsor clean energy legislation. It currently endorses 24 members of the House.

“There’s been a lot of pressure on Republicans to vote like Democrats -- to vote for overhauls and massive federal programs,” said Reams. “I get why Republicans don’t get it, and I want to help them navigate that, to get to a place where they can say, ‘I never thought about that.’”

Last year CRES released an ad encouraging President Trump to stay in the Paris climate agreement, which featured support from top executives and members of the White House business advisory council.

Unlike most clean energy lobbying groups, CRES has a record of spending millions of dollars exclusively on Republican candidates. That spending has “accelerated our authenticity and believability of who we are,” said Reams.

At a hearing Tuesday for the routine assessment of major utilities’ long-term resource plans, regulators rebuked the proposals and instituted a nine-month moratorium on new gas plants larger than 150 megawatts.

The commissioners are in the midst of examining an energy system overhaul to pursue 80 percent clean energy with a focus on energy storage to meet peak power with clean sources. The building freeze will prevent near-term investments in gas infrastructure that could become stranded assets if the grid overhaul comes into force.

Halting gas construction was an unusual move, especially for a panel of five Republicans in a state without a political mandate to tackle emissions from electricity, as seen in California or Massachusetts. Indeed, the nine-month freeze appears to be the first of its kind.

In contrast to the recently proposed grid reform, the utilities’ Integrated Resource Plans, originally submitted last year, relied primarily on natural gas for keeping the lights over the next 15 years.

Arizona Public Service, for instance, calls for more than 5,000 megawatts of natural gas additions (some of which replace retiring capacity), but negligible new utility-scale renewables. The plan does anticipate 3,315 megawatts of distributed solar, though, and several hundred megawatts of energy storage.

In Arizona, the utility regulators don’t approve or reject IRPs, they “acknowledge” them, or not.

“This is the first time the Commission did not acknowledge the utility IRPs,” said Jeff Schlegel, who testified at the meeting on behalf of the public interest group Southwest Energy Efficiency Project. “For the Commission to not acknowledge meant essentially that they had some pretty serious concerns with what’s in the utility plans.”

The regulators then made their concerns explicit in an amendment that called on the utilities to consider a scenario where fossil fuel additions are capped at 20 percent.

Another amendment asks them to model a case with 1,000 megawatts of energy storage, 50 percent clean energy and 20 percent demand side management. That mix of resources more closely resembles the grid overhaul proposed in January by Commissioner Andy Tobin.

APS didn't have any plans to build new gas facilities in that timeframe, said Greg Bernosky, director of state regulation and compliance, so the moratorium will not affect any utility operations. The decision also applies to Tucson Electric Power and UNS Electric.

Fast times on the Arizona grid

Tuesday's outcome highlights a difficulty of the energy transition: utility planning takes a long time, while new energy technologies move very fast.

"It’s a multi-year process, so information gets outdated," Bernosky said of the IRP process. He supports a Commission decision Tuesday to begin streamlining the IRP process.

As a result of that procedural pace, the vision described in APS' plan, based on the view from Q3 2016, now looks out of date compared to APS' own actions.

Last month, the utility announced a groundbreaking solar-plus-storage plant to be built by First Solar, which will store solar production in a 50-megawatt battery to dispatch precisely during the summer peak hours of 3 to 8 p.m.

That project won an open-ended request for proposals, beating out gas plants and standalone solar and batteries. In doing so, it exceeds the IRP's expectations for new batteries and utility-scale solar in the next five years.

"When we went to market and saw what was available to meet the need, that project was there and we were able to obtain it," Bernosky said.

That experience reveals a disconnect between the official projections of grid planning and what's available now from the clean energy industry. The utility won't insist on outdated projections in the face of changing market dynamics, Bernosky added.

"The IRP is a planning document -- it’s not a rigid, static document," Bernosky said. "It’s something we use to look out over a period of time, but we are making short-term procurement decisions based on what is available in the market and what meets our customer and system needs."

The right kind of solar

Still, the planning document carries weight as an expression of where the utility thinks its energy mix is heading. It's already looking probable that the next iteration will differ in significant ways.

APS remains skeptical of standalone, utility-scale solar. Given the expected influx of distributed solar, the grid will see a large influx of generation in the middle of the day that drops off before the evening peak hours. APS isn't interested in simply getting more surplus generation at noon.

"If we were to just keep doing more solar without that blend of [storage] technology, we would be almost causing more harm to the system or additional costs to customers," Bernosky said. "The ability to catch and release solar with that technology pair is really exciting to us now and we'd love to see more in the future."

A year or two ago, that asset hadn't materialized, and APS turned primarily to gas as the future tool to balance the fluctuations of solar. In the meantime, APS itself has proven that another option exists and can even beat a gas plant's economics.

The utility does not have any procurement processes going on currently, but is evaluating what will come next, said Jeff Burke, director of resource planning. New rounds of procurement, in turn, will inform future planning efforts.

The commissioners' skepticism will influence which investments Arizona utilities can expect to get rate recovery on in the coming years, said Stacy Tellinghuisen, senior climate policy analyst at Western Resource Advocates. That organization modeled a high renewables scenario for APS that it says would save ratepayers roughly $300 million compared to the official IRP.

"I hope that we will see the utilities put out RFPs for clean energy resources to meet their growing loads," she said.

APS has also pursued ways to procure capacity from merchant gas plants in shorter time increments, Bernosky said, like seven years instead of 20. That allows the utility to get capacity it needs in the short term without committing to an unnecessary expense in the long run. But, he noted, that was not described clearly in the last IRP.

Thursday, March 15, 2018

The Federal Energy Regulatory Commission pleased almost every sector of the energy industry -- except for coal and nuclear power plant owners -- with its unanimous decision to reject Energy Secretary Rick Perry’s plan to offer price supports to baseload power plants in the name of grid resilience.

But last week’s 3-to-2 vote approving ISO New England’s new market pricing proposal has reignited fears among clean energy and consumer advocates that FERC is setting the stage to preempt state clean energy policies in the name of market fairness.

Last week’s order (PDF) was narrowly approved, with Trump appointees Ray McIntyre Neil Chatterjee approving, and commissioners Richard Glick, a Democrat, and Robert Powelson, a Republican, dissenting.

With the approval, ISO-NE is free to proceed with a plan to split its capacity market bidding into two parts. The market reform, dubbed Competitive Auctions with Sponsored Policy Resources (CASPR), is a complicated effort to balance zero marginal-cost wind and solar power against fossil fuel and nuclear-powered generators for bidding to provide power in years to come.

Much like a similar proposal from mid-Atlantic grid operator PJM, ISO-NE’s plan has drawn the fire of clean energy and consumer advocates, since it’s likely to lead to higher power prices and increase the competitiveness of dirty power plants. Grid operators have argued that traditional market constructs, which set prices based on marginal generation costs, aren’t properly valuing baseload resources.

Commissioner Cheryl LaFleur, a Democrat and the only remaining Obama appointee, issued a separate concurrence, providing the third yes vote to pass the order. But in separate statements, both LaFleur and Glick dissented on a particular part of the order -- Paragraph 22, to be specific.

In that paragraph, the commission writes: “Absent a showing that a different method would appropriately address particular state policies, we intend to use the MOPR to address the impacts of state policies on the wholesale capacity markets.” This seemingly bland sentence represents a potential bombshell for state energy policies.

MOPR stands for "minimum offer price rule," a market mechanism that sets minimum prices for bids into energy or capacity markets, to prevent market manipulators to inject artificially low prices into the market.

But they’re a very problematic model to use when talking about zero marginal-cost wind and solar energy -- and both Glick and LaFleur are against using MOPR as a blanket approach to properly pricing clean energy against fueled power plans.

This issue has been a hot topic of debate among FERC stakeholders since it was introduced for discussion last May. Back then, Environmental Defense Fund's Michael Panfil told us that he and other groups supported a “limited MOPR," one that’s restricted to a particular use in markets.

But expanding the concept of a MOPR without these kinds of specific limits could impose on state energy policy, he warned. That’s because MOPRs could start to prevent clean energy resources from participating in capacity markets, and thus undermine the state policies that are supporting their growth.

In an email this week, Robbie Orvis, policy director at Energy Innovation, wrote that “Essentially, FERC proposed to address state policy by accommodating proposed market reforms that attempt to undo state policy. In ISO-NE’s case, the capacity market reforms put renewables at a disadvantage while raising costs for customers, all so that existing generators can squeak more money out of the market, which ISO-NE acknowledges is oversupplied.”

Natural Resources Defense Council clean energy attorney Miles Farmer responded to Friday's order by accusing commissioners Chatterjee and McIntyre of “contemplating an unprecedented power grab, seeking to coerce states into abandoning or modifying their energy policies.”

Farmer tweeted about how ISO-NE’s application of a MOPR could undercut state clean energy policies: “FERC’s CASPR order declares that by default, FERC will apply MOPR not only to market manipulators, but also to resources who submit low offers because they are supported by a state policy,” he wrote. “In many cases, this minimum offer price calculated by FERC will be too high to ‘clear’ (be chosen) in the market, and thus the generator won’t be able to sell any of its capacity, even though it is being supported by the state and is in fact able to supply capacity.”

Commissioner Glick agreed that a blanket use of the MOPR “is ill-conceived, misguided, and a serious threat to consumers, the environment and, in fact, the long-term viability of the Commission’s capacity market construct,” he wrote in a dissent attached to Friday’s order. “The suggestion in today’s order that the Commission will rely on MOPRs -- or something similar -- to mitigate the impacts of state public policies will eventually come to rank as a historically serious misstep.”

Glick wrote that FERC should instead “stop using the MOPR to interfere with state public policies and, instead, apply the MOPR in only the limited circumstance for which it was originally intended: to prevent the exercise of buyer-side market power.”

In a separately released statement, LaFleur noted that, despite her yes vote on the order, “I reject the notion, however, that we should use the MOPR as a 'standard solution' -- a blunt instrument -- against the impacts of all state policies.” She suggested alternatives, such as limited MOPRs, or even pricing carbon-neutral resources, as other grid operators such as New York ISO are contemplating.

And as Glick wrote, adding LaFleur’s dissent of the MOPR to his and Powelson’s dissents of the order itself means that the policy of using the MOPR as a blanket approach “is not adopted by a majority of the Commissioners that support the order.”

This unusual situation -- a split decision on different parts of an order that was passed with a bare minimum of yes votes -- is likely to lead to legal challenges to the order. Former FERC commissioner Norman Bay wrote on Twitter that opponents to ISO-NE’s CASPR proposal are likely to redouble their efforts for a rehearing, and cite the “fractured vote” as a cause for legal appeals.

Meanwhile, mid-Atlantic grid operator PJM, the country's largest, has two capacity proposals before FERC, noted Energy Innovation's Orvis: a two-part auction similar to CASPR, and an expansion of its MOPR. That will set the stage for the next big debate over how to manage the shifting balance of supply and demand, in a grid market that encompasses many of the coal-fired and nuclear power plants that have been petitioning the federal government for relief.

Separately, PJM is also asking FERC to approve an energy market price formation proposal that has drawn fire from clean energy and consumer groups, since it would increase total energy and capacity market costs from 2 to 5 percent, largely in higher prices that would benefit baseload power plants. In its Friday filing to meet FERC's demand for a report on grid resilience, PJM stated that its proposed market change, is an "important and inter-related component of ensuring grid resilience," indicating that it intends to link the two issues from now on.

The Energy Department’s Office of Energy Efficiency and Renewable Energy (EERE) is so successful that its funding should be diverted elsewhere, said the agency’s Under Secretary of Energy Mark Menezes.

“In the area of EERE…we have been meeting or exceeding our goals” over the last five years, said Menezes, who spoke at The American Council on Renewable Energy’s Renewable Energy Policy Forum in Washington, D.C. on Wednesday. He praised the office for helping reduce the cost of electric-vehicle batteries, wind and solar technologies.

“Our job is to have early-stage research and move it along the technological readiness levels, eventually getting it to where it’s commercially deployable. But once it’s commercially deployable, then the question becomes: What role does the department need to spend?” he said.

“To be sure, you could continue spending money there, but then where would be the opportunities for new energy breakthroughs?” he asked.

The Trump administration’s 2019 budget proposal released in February slashes funding for several clean energy programs, including EERE and the Advanced Research Projects Agency-Energy (ARPA-E). According to numbers released by DOE, the EERE would receive $696 million, a cut of $1.3 billion below its 2017 budget. The administration proposed eliminating ARPA-E altogether.

The plan has been widely criticized by clean energy advocates for failing to adequately consider climate change and the shifting tides of the energy industry.

Menezes’ rationale for gutting EERE funding is “like stopping research in home-movie technology after the VCR,” wrote Elizabeth Noll, a legislative expert for the Natural Resources Defense Council, in a blog post this week. “Wind, solar, energy storage and other clean technologies are at the VCR phase -- and Secretary Perry’s budget stands in the way of the United States reaping the rewards that come with further developing them here at home.”

As Energy Under Secretary, Menezes is tasked with advising Energy Secretary Rick Perry on clean energy technologies and research initiatives.

According to the DOE’s own estimates, $12 billion in EERE funding has yielded a net economic benefit of over $230 billion, with an annual return on investment of more than 20 percent.

“They just can’t win -- can’t be too successful or funding is slashed. Effective programs are penalized for success,” tweeted Jamie Nolan, a former government contractor who served as communications director for the DOE’s SunShot Initiative and attended Wednesday’s conference.

Energy Secretary Rick Perry is scheduled to defend the administration’s 2019 budget proposal before a House Appropriations subcommittee on Thursday. The secretary distanced himself from the 2018 budget proposal last year, telling the Senate Energy and Natural Resources Committee it "was written before I got here."

While renewable energy programs are being targeted for cuts, Trump’s budget proposal would increase funding for high-efficiency coal plants and small modular units by 50 percent. The agency specifically plans to establish competitive funding opportunities for small and modular coal-fired power plants. Smaller coal plants would fit better into an evolving electricity system with increasing amounts of intermittent wind and solar power, said Steve Winberg, assistant secretary for fossil energy at the DOE.

The problem is, small modular coal plants are largely unheard of, and they may never make economic sense, according to analysts.

The president's proposed budget has virtually no chance of being enacted as written. Ultimately, it will be up to Congress to decide what government spending looks like, and last year lawmakers sidestepped many of the drastic cuts asked for by the administration.

“I will be fighting with my colleagues to provide full EERE funding in next week’s omnibus,” said Sen. Maria Cantwell (D-Wash.), the ranking Democrat on the Senate Energy and Natural Resource Committee, who also spoke at the ACORE event. “We are working with our colleagues to try to accelerate, even if it’s only piece by piece, the investment in [research and development] that’s needed.”

A bid by tech giant Microsoft to become the largest distributed solar offtaker in Singapore sounds ambitious. But it could actually be safer than buying a utility-scale project, according to Brian Janous, Microsoft's general manager of energy.

Earlier this month, Microsoft announced plans to procure 60 megawatts of solar energy in Singapore.

Speaking The Interchange podcast this month, Janous told GTM that plans to source that capacity from rooftop solar would not be as risky as trying to get the whole amount from a single plant.

“There is a small amount of volume risk,” he said. “But what you don't have is the risk that the entire project doesn't get developed. We've had other projects that have had challenges related to permitting issues that may put in jeopardy 100 percent of the output."

“With this one, because it is distributed, in some ways you reduce that development risk. You might have slightly more uncertainty -- is it going to be 60 megawatts or 58 megawatts? But you're distributing some of that exposure you have in traditional development projects," explained Janous.

In the Interchange interview, Janous also talked about Microsoft's outlook for battery storage and pairing renewable energy directly with localized demand at facilities around the world.

The procurement agreement, with Singaporean PV developer Sunseap Group, marks Microsoft’s first clean energy deal in Asia and will create the largest solar portfolio in Singapore to date, Microsoft said.

The buildout, which will span “hundreds of rooftops across the nation,” according to Microsoft, is also said to be the first rooftop solar portfolio in the country focused on serving data center energy consumption.

“Our cloud services are helping to power Singapore’s digital transformation, and today’s agreement will ensure that transformation is increasingly powered by clean energy,” said Kevin Wo, managing director of Microsoft Singapore, in a press release.

Microsoft, which has more than 850 employees in Singapore, will not own the solar plants itself, said Janous. Instead, it will buy 100 percent of the energy produced by solar plants built, owned and operated by Sunseap, over a 20-year period.

Microsoft was forced to look at distributed generation because there was simply not enough space for utility-scale projects in Singapore, Janous said. “We were really limited to just looking at what is available, and in Singapore it's rooftops,” he commented. “That was the only clear route we had to get to a material amount of energy.”

Another problem for Microsoft was that it needed much more space than could be found on its own buildings. Microsoft’s data centers are about the size of a Walmart supercenter, said Janous, but “we're consuming 10 to 20 times the amount of electricity.”

The amount of energy that could be generated on Microsoft’s data center rooftop space in Singapore would only serve the adjacent offices, he said. The company’s Singapore data centers deliver Microsoft Azure, Office 365 and numerous other cloud services for customers.

The deal is Microsoft’s third international clean energy announcement, following two wind deals announced in Ireland and The Netherlands in 2017.

Once operational, the new solar project will bring Microsoft’s total global direct procurement in renewable energy projects to 860 megawatts, said Christian Belady, general manager for cloud infrastructure strategy and architecture at Microsoft.

The Singapore deal puts Microsoft on track to power 50 percent of its global data center load with renewable energy this year, he added.

The contract is also a major coup for Sunseap, which in January signed a 21-year power-purchase agreement for 4 megawatts of generation with port operator PSA, and has assets including a 140-megawatt solar farm in India and a 10-megawatt PV project in Cambodia.